Recovering hydrocarbons from subterranean zones relies on drilling wellbores. In subsurface drilling, drilling equipment situated at the surface drives a drill string to extend from the surface equipment to the formation or subterranean zone of interest. The drill string is typically made up of metallic tubulars. The drill string may extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling, or extending, the wellbore.
The surface equipment typically includes some sort of drilling fluid system. In most cases a drilling “mud” is pumped through the inside of the drill string. The drilling mud cools and lubricates the drill bit, exits the drill bit and carries rock cuttings back to the surface. The mud also helps control bottom hole pressure and prevents hydrocarbon influx from the formation into the wellbore and potential blow out at the surface.
Directional drilling permits the path of a wellbore to be steered. Directional drilling may be applied to steer a well from vertical to intersect a target endpoint or to follow a prescribed path. A bottom hole assembly (BHA) at the terminal end of the drillstring may include 1) the drill bit; 2) a steerable downhole mud motor of a rotary steerable system; 3) sensors of survey equipment for logging while drilling (LWD) and/or measurement while drilling (MWD) to evaluate downhole conditions as drilling progresses; 4) apparatus for telemetry of data to the surface; and 5) other control equipment such as stabilizers or heavy weight drill collars.
MWD equipment may be used to provide downhole sensor and status information at the surface while drilling in a near real-time mode. This information may be used by the rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, hydrocarbon size and location. These decisions can include making intentional deviations from the planned wellbore path as necessary, based on the information gathered from the downhole sensors during the drilling process. In its ability to obtain real time data, MWD allows for a relatively more economical and efficient drilling operation.
Various telemetry methods may be used to send data from MWD or LWD sensors back to the surface. Such telemetry methods include, but are not limited to, the use of hardwired drill pipe, acoustic telemetry, use of fibre optic cable, mud pulse (MP) telemetry and electromagnetic (EM) telemetry.
EM telemetry involves the generation of electromagnetic waves at the wellbore which travel through the earth and are detected at the surface.
Advantages of EM telemetry relative to MP telemetry, include generally faster data rates, increased reliability due to no moving downhole parts, high resistance to lost circulating material (LCM) use, and suitability for air/underbalanced drilling. An EM system can transmit data without a continuous fluid column; hence EM telemetry can be used when there is no mud flowing. This is advantageous when the drill crew is adding a new section of drill pipe as the EM signal can transmit the directional survey while the drill crew is adding the new pipe.
Disadvantages of EM telemetry include lower depth capability, incompatibility with some formations (for example, high salt formations and formations of high resistivity contrast), and some market resistance due to acceptance of older established methods. Also, as the EM transmission is strongly attenuated over long distances through the earth formations, it requires a relatively large amount of power so that the signals are detected at surface. Higher frequency signals attenuate faster than low frequency signals.
A metallic tubular is generally used as the dipole antennae for an EM telemetry tool by dividing the drill string into two conductive sections by an insulating joint or connector which is known in the art as a “gap sub”.
WO 2010/121344 and WO 2010/121345 describe drill bit assembly systems which incorporate channels through an electrically isolating gap between the drill bit head and pin body to provide a feed through for a wire that may carry information for uplink communication from the drill bit, or downlink communication from an uphole EM gap subassembly. WO 2009/086637 describes a gap sub having an insulated wire extending through the gap sub.
U.S. Pat. No. 6,866,306, U.S. Pat. No. 6,992,554, U.S. Pat. No. 7,362,235, US2009/0058675, US2010/0175890, US2012/0090827, US2013/0063276 and WO2009/032163 disclose various constructions for carrying data signals between sections of a drill string. WO2009/0143405 and WO2010/065205 disclose the use of repeaters to transmit signals along a drill string. US 2008/0245570; WO 2009/048768A2; U.S. Pat. No. 7,411,517; US2004/0163822A1; and U.S. Pat. No. 8,334,786 disclose downhole systems.
Despite work that has been done to develop systems for subsurface telemetry there remains a need for practical and reliable subsurface telemetry systems.